ML20209F091
| ML20209F091 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 07/09/1985 |
| From: | FLORIDA POWER CORP. |
| To: | |
| Shared Package | |
| ML20209F077 | List: |
| References | |
| GL-85-02, GL-85-2, PROC-850709, NUDOCS 8507120386 | |
| Download: ML20209F091 (24) | |
Text
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DESCRIPTION OF FLORIDA POWER CORPORATION'S OVERALL PROGRAM FOR ASSURING STEAM GENERATOR INTEGRITY AND STEAM GENERATOR TUBE LEAK MITIGATION July 9,1985 l
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l 8507120386 850709 ADOCK 05000302 PDR PDR p
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CONTENTS SECTION PAGE
1.0 INTRODUCTION
1-1 2.0 MANAGEMENT PHILOSOPHY 2-1 3.0 SECONDARY SYSTEM DESCRIPTION L1 3.1 CONDENSATE MAKEUP L1 3.2 MAIN CONDENSER L1
. 3.3 DEMINERALIZERS L1 3.4 FEEDWATER HEATERS L1 3.5 DEAERATOR L2 3.6 STEAM GENERATORS L2 3.7 MOISTURE SEPARATOR REHEATERS 3-2 4.0 STEAM GENERATOR INTEGRITY PROGRAM 4.1 STEAM GENERATOR TASK FORCE.
41 4.1.1
Background
4-1 4.1.2 Activities 4-1 4.2 SECONDARY SYSTEMS OPERATIONS AND PLANT REVIEW PROJECT TEAM 4-5 4.3 PREVENTION AND DETECTION OF LOOSE PARTS 4-5 4.3.1 Secondary Side Visual Inspections.
4-6 4.3.2 Quality Assurance / Quality Control Procedures 4-6 4.4 STEAM GENERATOR TUBE INSERVICE INSPECTION 4.4.1 Full Length Tube Inspection 4-7 4.4.2 Inservice Inspection Interval 4-7 4.5 SECONDARY WATER CHEMISTRY PROGRAM 4-7 4.5.1 Chemistry Control 4-8 4.5.2 Data Interpretation / Action Initiation Contact 4-10 4.5.3 Analytical Methods bl0 4.5.4 Data Management bil 4.5.5 Surveillance bil 4.6 CONDENSER INSERVICE INSPECTIONS bl2 4.6.1 Procedure bl3 4.6.2 Leak Identification and Location b13 4.6.3 Leak Repair 4-13 4.6.4 Leakage Cause Determination bl4 4.6.5 Preventative Maintenance 4-14' 3.0 STEAM GENERATOR TUBE RUPTURE MITIGATION 5.1 PRIMARY-TO-SECONDARY LEAKAGE LIMITS 5-1 5.2 COOLANTIODINE ACTIVITY LIMIT 5-1 5.3 SAFETY INSPECTION SIGNAL RESET L1 APPENDIX Request for Information Concerning Category C-2 A-1 Steam Generator Tube Inspections J
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1.0 INTRODUCTION
NRC Generic Letter 35-02, " Staff Recommend Actions Stemming from NRC Integrated Program for the Resolution of Unresolved Safety Issues Regarding Steam Generator Tube Integrity", requested a description of Florida Power Corporation's "overall program for assuring steam generator tube integrity and for. steam generator tube rupture mitigation" at Crystal River Unit 3.
This report is the requested program description.
Florida Power Corporation (FPC) considers its overall steam generator program -
to be very effective. and is pleased to describe it to the Staff. However, it.
should be understood that this document is a vehicle for conveying information only, and neither states nor implies any commitments to the Staff. In addition it should be noted that this report summarizes what FPC considers.to be the major ongoing activities and programs relative to the concerns of Generic Letter 85-02, and does not represent a complete description of all such activities and programs.
FPC recognizes that the Staff is aware of many of the corrosion and fouling mechanisms briefly described in this report. The purpose for such descriptions is to state the technical basis for the performance of each activity that is included in FPC's efforts to assure steam generator integrity. These descriptions thus demonstrate to the Staff FPC's cognizance of steam generator corrosion and fouling concerns and states the rationale for its steam generator. integrity efforts.
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12.0 MANAGEMENT PHILOSOPHY
' Management is committed to the safe, legal, and economical operation of Crystal River Unit 3 (CR-3). Consistent with that commitment is the assurance -
c of steam generator integrity. While FPC management views maintaining the integrity of the steam generators as primarily an issue of economic merit and secondarily that of safety, significant human and economic resources have been and will continue to be (as necessary) utilized to assure steam generator integrity.
I Foremost of management's concerns relative to steam generators is the fouling / pressure drop problem which resulted in CR-3 being load limited the last few months of the past operating cycle. Considerable time, effort, and money l
(about $2,500,000 over the past 12 months) has been spent om 1.
Developing (jointly with Arkansas Power & Light) and employing an innovative, proprietary process to remove all or part of the crud which is deposited in the broached holes of the tube support plates and is thought to be the cause of the load limitation.
2.
Attempting to identify and understand the fouling mechanism (s).
3.
Develop programmatic _ changes or equipment modifications that will reduce or eliminate the transport of fouling and corrosive species into the steam generators.
T It should be emphasized that all of the above efforts (1-3) were and are being performed without any regulatory requirements mandating such. These actions,
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therefore, demonstrate management's strong commitment and ability to ensure the long-term integrity of the steam generators without waiting for the Staff to outline a steam generator integrity program for FPC to follow. Furthermore, the above efforts demonstrates FPC's ability and commitment to work with other utilities to resolve generic concerns.
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While the elimination of the load limitations due to fouling has of late received lI much management attention, management is aware that fouling creates an environment in the steam generator that is potentially favorable to various yl -
corrosion mechanisms (e.g., underdeposit corrosion). Therefore, any action taken t
L to reduce fouling-and remove the fouling deposits from the steam generators will also reduce the potential for. steam generator tube degradation and rupture by such corrosion mechanisms.
Management is aware of the necessity of maintaining good secondary water chemistry and a " tight" condenser in order to avoid the introduction of corrosion-causing contaminants into the steam generators. - The current fouling problem has intensified management awareness of the roles water chemistry and condenser integrity play, not only in steam generator corrosion, but also in steam
- generator iouling.
Lines of communication always exist between the technical staff 'and i
management whereby concerns and recommendations of technical personnel j
relative to steam generator integrity may be voiced. Management is responsive
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to these concerns and recommendations, and typically creates a task force or r
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working group to investigate or address major concerns. The formation by management of the Steam Generator Task Force and the Secondary Systems Operations and Plant Review Project Team (see Sections 4.1 and 4.2,
-respectively) exemplify management's responsiveness to its technical staff, as well as its dedication to maintaining steam generator integrity.
In summation, FPC management is committed to maintaining steam generator integrity, and will continue to give direction to assure implementation of programs that are consistent with that commitment and the philosophy of safe, legal, economical operation.
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3.0 SECONDARY SYSTEM DESCRIPTION This section briefly describes the major components of the CR-3 secondary system, the purpose being to facilitate Staff identification of differences in the CR-3 plant configuration (as compared with other PWRs) which favorably affect steam generator integrity. A simplified flow diagram of the CR-3 secondary system is shown in Figure 3-1.
3.1 CONDENSATE M AKEUP l
Makeup water for both primary (reactor) and secondary cooling systems is obtained from fresh water wells near the CR-3 site. This water is purified by the makeup feed demineralizers located on the site of Crystal River Unit 1 (an adjacent fossil unit). The demineralized water is stored on site at Unit I until it is pumped to the CR-3 Condensate Storage Tank (CST). The CST is vented to the atmosphere. FPC plans to build an emergency feedwater (EFW) storage tank during Refuel VI (currently the CST is the source for the EFW.) This new tank will be a seismically qualified safety grade tank with a vacuum degasifier and filtration system to maintain water quality. The CST will still be used for condensate makeup and gland seal water.
3.2 M AIN CONDENSER CR-3 has a twin shell (4 waterboxes) single pass surface condenser with approximately 42,000 B-111 Alloy 715 (70-30 Cu-Ni) tubes. The tubesheets are constructed of Type 316 stainless steel and the waterboxes are of Type 304 stainless steel. Sacrificial anodes are employed to prevent galvanic corrosion of the waterboxes and tubesheets.
The cooling water temperature differential across the condenser is limited to 17.50F by EPA regulations. The condenser was designed to maintain the concentration of dissolved oxygen in the two condenser hotwells at d 5 ppb.
3.3 CONDENSATE DEMINERALIZERS Condensate /feedwater purification is performed by the use of six (6) full-flow condensate demineralizers containing mix bed cation / anion resins. Five units are normally in operation when the plant is at full power, and are replaced whenever the conductivity or sodium concentration in the effluent of each demineralized bed exceeds 3 y mhos/cm or 2 ppb, respectively. ' Depleted resin is sluiced and replaced with new resin which eliminates the introduction of sulfate, sodium, or hydroxide ions and resin particles into the feedwater from resin regeneration.
3.4 FEEDWATER HEATERS f
There are two parallel flow paths (A and B) for feedwater heating (see Figure 3-1). At CR-3 feedwater heating is accomplished by Low Pressure (LP) Heaters 1,2, and 3 (LP Heaters 1 and 2 are located in the neck of each section (A and B) of the main condenser), the deaerating heater (Heater 4), Intermediate Pressure (IP) Heater 5, and High Pressure (HP) Heater 6. The LP Heaters 1,2, and 3, IP Heater 5, and HP Heater 6 are U-tube heat exchangers with Type 304 or 304L stainless steel tubes. The deaerator vessel is carbon steel with stainless steel deaerating trays. The drains to LP Heaters 1, 2, and 3 are cascaded backwards to the condenser for cleanup by the condensate demineralizers. The drains to HP Heater 6 and IP Heater 5 cascade backwards to the deaerator.
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3.5 DEAERATOR The. dtaerator ' functions as the fourth feedwater heater and also removes dissolved. gases (O2, CO2) from the feedwater to control corrosion.
The deaerator vessel is carbon steel with stainless steel deaerating trays.
3.6 STEAM GENERATORS The two once-through-steam generators (OTSGs) have Inconel 600 tubes and produces steam that is superheated 60oF. Except for one incident in 1978, the OTSGs have operated without problems. During the initial fuel cycle a tube-to-tubesheet seal leak developed in the "B" steam generator as the result of a loose burnable poison rod in the reactor and migration of debris to the steam generator. Degraded tubes were isolated by plugging.
During the present refueling outage (Refuel V), two (2) 4-3/4" inspection ports were installed in the "A" steam generator. One port was placed midway between the 3rd and 4th tube support plates' (TSPs),~ the other midway between the 5th and 6th TSPs. This modification allowed an extensive video inspection of the steam generator internals and the acquisition of crud samples from the broaches of several TSPs. Future video inspections and crud sample acquisition (and analysis) are thus possible through these ports and will permit:
1.
Identification of new fouling / corrosion mechanisms (i.e.,
corrosion mechanisms that exist but may not become apparent for several operating cycles).
2.
An evaluation of the effectiveness of chemistry and operational programs developed to reduce deposition of contaminants in the steam t;enerator.
3.7 MOISTURE SEPARATOR REHEATERS The moisture separator reheater tubes are constructed of 90-10 Cu-Ni tubes.
The moisture removed from the wet-incoming steam (from the High Pressure Turbine exhaust) is drained to the condenser hotwell for cleanup (rather than adding it to the feedwater). This action ensures a higher quality of feedwater but entails a power penalty of about 4-8 MWe.
FPC's commitment to maintaining -good secondary water chemistry and long-term steam generator integrity is thus demonstrated by.this action.
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STEAM GENERATOR INTEGRITY PROGRAM 4.1 STEAM GENERATOR TASK FORCE 4.1.1
Background
In January 1983 management formed a Steam Generator Task Force to solve the problem of the gradual increase in the operating water level in the feedwater annulus (this continued increase resulted in a reduction of the maximum power achievable at CR-3 during the last few months of the last operating cycle),
thought-to be caused by increased pressure drop in the two phase region of the steam generator bundle due to partial or complete blockage of the broaches in the tube support plates by accumulated corrosion products. The objectives of the Task Force were somewhat redefined in August 1984 to be as follows:
1.
Develop chemistry and operational programs to reduce carryover of fouling and corrosive contaminants into the steam generators.
2.
Develop long-range improvements to secondary side components (e.g.,
feedwater heaters, deaerator, condens-r) to minimize fouling of the steam generators and the potential for corrosion of steam generator internals.
3.
Develop safe (chemical and non-chemical) methods to remove the corrosion products fouling both steam generators.
An aggressive program to meet these objects was launched by the Task Force subsequent to its formation. The activities of this program are briefly described in Section 4.1.2.
The Task Force is composed of several multi-disciplined FPC engineers and technicians. Technical assistance to the Task Force is provided (as -
needed) by the NSSS vendor (Babcock & Wilcox), engineering consultant firms, and other FPC personnel.
The Steam Generator Task Force Chairman currently reports directly to the Director, Site Nuclear Operations, and is responsible for ensuring that the objectives of the Task Force are being met.
it should be noted that, although the Task Force is charged to ensure the long term integrity of the steam generators and to minimize or eliminate the loss of power generation due to steam generator fouling, other groups within FPC are also working to meet the aforementioned objectives. Hence the Task Force in the performance of its tasks interfaces extensively with, and provides assistance as necessary to corporate and plant engineering, chemistry, operations, training, 3
and maintenance personnel.
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4.1.2 Activities i
Major ongoing and completed activities of the Steam Generator Task Force are i
summarized below, Future activities of the Task Force will be based on the
.t success of ongoing activities and will be consistent with the Task Force's i
objectives.
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4.1.2.1 Condenser Retube Study The Task Force is fully aware that nuclear industry experience has demonstrated that steam generator integrity is affected by condenser integrity and materials of construction. Cooling water impurity inleakage (as a result of a leaking condenser) and corrosion product transport (dependent in part on the materials of construction of secondary side components such as the condenser) result in a
" breeding ground"in the steam generators for such corrosion mechanisms as tube cracking, tube denting / support plate corrosion, and tube pitting in addition to the fouling / pressure drop problem which has been experienced at CR-3. In addition, the Task Force understands the role that copper plays as a strong oxidizing species which promotes other corrosion mechanisms in the steam generator (e.g.,
denting). The Task Force is, therefore, actively involved in FPC's condenser retube study to ensure that only non-copper alloy tubes, tube /tubesheet alloy combinations, and tube installation methods with a proven record of success are employed.
4.1.2.2 Raise Feedwater pH lt is thought (and recent video-inspections of the "A" steam generator lends credence to this idea) that the cause of the operating water level increase in the feedwater annulus (which limited the maximum achievable power for the last few months of the past operating cycle) is an increased pressure drop in the two phase region of the steam generator tube bundle due to partial or complete blockage of the broached hole openings in the tube support plates by accumulated corrosion -products.
Additionally, it is thought that corrosion product, accumulation in the steam generators provides a mechanism for concentration of impurities and for uncontrolled local corrosion. Accordingly, the Steam Generator Task Force, in conjunction with Chemistry personnel, initiated a program in August 1984 to reduce the transport of iron oxides to the steam generators by raising the feedwater pH from 9.0 to 9.2.
This program resulted in a very substantial reduction in corrosion product input to the steam generators (a 60% reduction in iron transport and virtually no change in copper transport, as compared with recent analysis of integrated samples and NWT
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Corporation findings in EPRI NP-2149).
4.1.2.3 Preliminary Chemical Cleaning Design The Task Force is currently working with engineering consultant firms to develop a preliminary design for chemically cleaning the CR-3 steam generators. This f
preliminary design will greatly facilitate the development of a detailed design in 1-the event management decides to chemically clean the CR-3 steam generators.
The preliminary design is based on employing the generic EPRI SGOG chemical cleaning solver.ts and process, as qualified by Babcock & Wilcox for Oconee-1 and ANO-1.. Supportive of the development of chemical cleaning technology within FPC, a letter of understanding with EPRI has recently been signed by
- management to permit the exchange of non-proprietary information relative to i-actual plant steam generator chemical cleanings.
4.1.2.4 Water Slap Cleaning Method The Task Force in conjunction with Arkansas Power & Light, several engineering l
service companies, and Babcock & Wilcox engineers, developed, qualified, and 4-2
employed in May 1985, a proprietary hydraulic steam generator cleaning method called." water slap". Comparison of the post-cleaning. video inspection results with pre-cleaning video inspection results indicate that a significant amount of blockage in the tube support plate broached holes was removed. FPC, therefore, anticipates a return to full or near full power at startup. It should be noted that a reduction in the potential for steam generator corrosion is also thought to have been obtained. inasmuch as the water slap cleaning method has removed significant amounts of fouling debris which is believed to provide a mechanism for concentration of impurities and uncontrolled local corrosion.
'4.1.2.5 Dispersant Polymers The Task Force is currently investigating the use of dispersant polymers as a means of removing corrosion products accumulated in the steam generators.
4.1.2.6 Steam Generator Inspection Ports In April 1985 two (2) inspection ports were installed in the "A" steam generator, one midway between the 3rd and 4th TSPs, and the other midway between the 5th and 6th TSPs.
The reasons for installing the inspection ports in these locations were:
(1) to identify. where the.. major blockage was occurring (thermodynamic analyses of the steam generator had concluded that the major blockage is at the fifth TSP; eddy current data suggested the 3rd TSP); (2) to maximize the cleaning effect of the " water slap" technique by identifying the TSP (s) with the major blockage and concentrate the cleaning effect on those TSP (s); and (3) to permit acquisition of crud samples from the TSPs with major blockage.
Future video inspections and steam generator crud sample acquisitions (and analyses) are made possible by the installation of these inspection ports and will allow:
1.
The identification of new fouling / corrosion mechanisms that may not become apparent for several%perating' cycles.
-n 2.
An evaluation of the effectiveness of chemistry and operational programs developed to reduce deposition of contaminants in the steam generators.
4.1.2.7 Video inspections Video inspections of the "A" steam generator were conducted through the newly installed inspection ports and through the lower handholes. In all, the lower tubesheet, the first and third through sixth tube support plates were visually inspected using state-of-the-art fiber optic techniques and equipment.
The inspections were two-fold in purpose: (1) To determine the effectiveness of the water slap cleaning method, and (2) To see in what form and where the corrosion products have deposited in the steam generator,information that once evaluated should lead to a better understanding of the fouling mechanism (s).
4.1.2.8 Secondary System Operations and Chemistry Review A year long review of secondary system operations and chemistry by an engineering consultant firm was initiated and funded by the Task Force. The 4-3
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purpose'of this review was to identify the operating practices, procedures and-
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design features for the existing secondary side system which may have an impact on-long term steam generator ' performance, and. to determine what improvements could be made to reduce the potential for corrosion and chemistry
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problems in this system, especially on the secondary side of the steam generator.
A total of 79 specific recommendations for improving secondary water. quality were made. Management created a project team (see Section 4.2) to review and implement obtainable recommendations.
4.1.2.9 Steam Generator Crud Sample Analysis -
Crud samples were obtained from several specific locations in the steam generator during the pre-cleaning video inspection. - In addition, samples of the crud removed by water slap were obtained.. These samples are currently being analyzed. The results of these analyses will promote a better understanding of the fouling mechanism and allow the development-and implementation of appropriate corrective action to minimize fouling and the potential for corrosion of the steam generators.
4.1.2.10 Recommendations to Management The Task Force makes recommendations, as necessary, to management.to implement various changes in plant operations or plant system modifications that will. reduce steam. generator fouling and the-potential for steam ' generator corrosion by reducing corrosion product and cooling water impurity transport to the steam generator, or that will enable crucial information to be-gathered that is necessary to better understand the fouling mechanism (s).
Management's responsiveness to Steam Generator Task Force recommendations is demonstrated by the fact that all of the above ongoing and completed activities were first Task Force recommendations to management. Keeping with its commitments to maintain the long term integrity of the steani generators and to safely, legally and economically operate CR-3, management authorized the implementation of these recommendat.ons.
-The successful performance of the aforementioned activities demonstrates that the Task Force can effectively work with other groups (e.g., Chemistry, Maintenance, Engineering) at CR-3. Furthermore, the dedication of the CR-3 plant staff and FPC Nuclear Operations in general to maintain the long term integrity of - the steam generators, is. demonstrated by these successfully completed programs.
FPC is proud to have made what it considers to be significant contributions to steam generator. cleaning technology and to have gained substantial data via video inspections and crud sample analyses relative to the fouling problem. This data' will no doubt very significantly contribute to the better understanding of fouling mechanisms in once-through steam generators.
It should be noted that the economic incentive to-assure steam generator integrity is indeed very great, and consequently regulatory action is not required.
FPC has demonstrated, by the above actions, its strong commitment and ability to assure steam generator integrity without Staff mandates or recommended actions.
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4.2 SECONDARY SYSTEMS OPER ATIONS AND PLANT REVIEW PROJECT TEAM In the Fall of 1983, the Steam Generator Task Force initiated sponsorship of a secondary systems operations and plant review. This review was conducted by an engineering service firm over the remainder of 1983 and throughout the entire year of 1984. The objectives of the review were two-fold:
1.
~ Identify operating practices, procedures and design features for the exising secondary site system at CR-3 which may have impact on long-term steam generator performance.
2.
Determine what improvements could be made to reduce the potential for corrosion and chemistry problems in the system, especially on the secondary side of the steam generators.
The final report was submitted to the Steam Generator Task Force and upper levels of management in January 1985.
The report made some 79 specific recommendations for improving - secondary water quality.
These recommendations consisted of procedure changes and plant modifications.
In February 1985, management decided to form a project team to control and track activities associated with resolution of the report's recomme1ations. The objectives of the project team are as follows:
1.
Segregate the recommendations into categories for subsequent action:
Immediate (quick actions with direct results)
Refuel V l
Short-term (418 months)
Long-term ( *18 months) 2.
Determine relative manpower and financial requirements for each recommendation.
3.
Assign responsibilities for tracking and resolution of each recommendation.
4.
Provide periodic updates. and presentations to staff and management concerning the progress of the team.
The Project Manager for the project team is the Manager, Site Nuclear Operations Technical Services, and reports directly to the Director, Site Nuclear Operations. He is responsible'for ensuring that the above objectives are met.
.Some of the recommended activities were performed during Refuel V.
The l-remainder.of the activities will be resolved by the project team in the future.
Ii 4.3 PREVENTION AND DETECTION OF LOOSE PARTS FPC recognizes the potential of loose parts in the steam generator to create SGTR events such as those experienced at Ginna and Prairie Island-1.
Accordingly, FPC has been and continues to be concerned with the prevention of l
loose parts from entering the steam generator, and the detection and removal (if nece:sary) of loose parts inadvertently introduced into the steam generator. It 4
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'It should be' noted that OTSGs are not as susceptible as recirculating steam generators to tube damage from loose parts due to (1) fewer parts in the OTSG; and (2) the filtering out of loose. parts from the feedwater train by the feedwater C
- nozzles and the circuitous flow path inside the steam generator itself. FPC's efforts' relative to -Staff Recommended Actions 1.a and 1.b (Section 2.1 of NUREG-0844) are described below in Sections 4.3.1 and 4.3.2, respectively.
p 4.3.1 A ~
Secondary Side V! mal Inspection -
i-The design of the B&W once-through steam generator is 4.3.1.1 Baseline inspection..
such that only those" peripheral tubes adjacent to the eight (8) lower steam i
_ generator penetdations (7 handholes and 1 manway) are readily accessible for inspection.' ; During the current outage (Refuel V), an inspection along -the l
periphery of the tube bundle was' performed through five (5) of the eight penetrations in the "A"-steam generator. This inspection revealed no indication of looseEparts.. Eddy current inspections of the peripheral tubes have been performed and yielded no indications of defects or degradation in the free span p
at or near the lower tubesheet.
Furthermore, no tubes in the "A" steam generator have been plugged due to damage by loose parts. There being no evidence to indicate a potential loose parts problem in the "A" steam generator, FPC, therefore, maintains that the " partial" visual baseline inspection performed is sufficient to meet the intent of Staff Recommended Action 1.a. Accordingly, there are no plans to conduct a visual inspection along the entire periphery of the tube bundle.
hhile such a visual inspection along the periphery of the tube bundle has not been performed in. the "B" steam generator, there is no compelling evidence to indicate a potential loose parts problem based on eddy current inspection. The lack of eddy current indications, together with the great risk of initiating corrosion by the unavoidable introduction of oxygen (while performing the baseline inspection) into a completely drained moist steam generator (the oxygen coming in contact with local contaminants could initiate corrosion heretofore not present), are-considered sufficient justification not to perform a visual baseline inspection of the,"B" steam generator.
14.3.1.2 Follow-up Inspections.
' A visual. inspection for loose parts following a o
modification or repair to a steam generator is required by procedures. Following the installation of the two inspection ports in the "A" steam generator, a visual
~ inspection was performed to look for any loose parts.that may have fell into the steam generator. No loose parts were found.
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4.3.2 Quality Assurance /Ouality Control Procedures Procedures exist that require detailed accountability of parts / tools that enter the steam generator on both the primary and secondary sides. These procedures are currently being reviewed by the Steam Generator Task Force and will be revised as appropriate.
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- 4.4 STEAM GENERATOR TUBE INSERVICE INSPECTION 4.4.I' Full Length Tube Inspection
. Staff Recommended Action 2.9 (Section 2.2.2 of NUREG-0844) applies only to U-tube type steam generators and is, therefore, not applicable to CR-3.
4.4.2 Inservice Inspection Interval The CR-3 Technical Specifications (T.S. 4.4.5.3) specify that, if two consecutive
-inspections following service under all volatile treatment (AVT) conditions, not including the preservice inspection, result in all inspection results f alling into the C-1 category, or if two, consecutive inspections demonstrate that previously observed degradation has not continued and no additional degradation has.
occurred, the inspection interval may be extended to a maximum of once per 40 months. Table 4.4-1, " Minimum Number of Steam Generators to be Inspected During Inservice Inspection", specifies' that the inservice inspection may be limited to one steam generator on a rotating schedule encompassing 6% of the tubes if the results of the first or previous inspections indicate that both steam-generators are performing in a like manner. This could result in an interval of 80 months between required inspections of an individual steam generator.
With regard.to Staff Recommended Action 2.b (Section 2.2.4 of NUREG-0844) which limits the msximum allowable time between eddy current inspections of an individual steam generator to 72 months, FPC has the following comments:
1.
The recommendation has much more meaning. for a 3-or 4-loop plant where inspection intervals could be as high as 120 and 160 months, respectively.
2.
Reducing the maximum allowable time between eddy current inspections of an individual steam generator from 80 months to 72 months would not significantly increase the public health and safety.
3.
Any significant steam generator problems would preclude the inspection interval from being increased to 80 months.
4.5
. SECONDARY WATER CHEMISTRY PROGRAM FPC is well' aware of the steam generator corrosion and fouling that can occur if ~
good secondary water chemistry is not maintained. Accordingly, the Chemistry Section at CR-3 is dedicated to maintaining the best possible chemistry controls to prevent ingress of impurities into the steam generators.
While FPC's secondary water chemistry program is not identical on a point-by-
. point basis with the EPRI secondary water chemistry guidelines, FPC's program does compare favorably-with the EPRI guidelines. Supportive of this evaluation are the conclusions of NRC Inspection Reports 84-08 and 85-10 which state:
"Although the SGOG/EPRI guidelines were not the basis for the licensee's water chemistry program, the program is very similar in most technical aspects,:i.e., control and diagnosis of water chemistry parameters.
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addition, most of the licensee's administrative policies are consistent with those recommended by SGOG/EPRI." (Inspection P.eport 85-10)
"It was the inspector's opinion that the lice..eie s. ster chemistry program covers all modes of plant operation and includes criteria, including limits on specified chemistry parameters, to minimize corrosion during layup, plant startup and shutdown, as well as during power operation." (Inspection Report 85-10)
"The inspector reviewed the scope of the surveillance programs for the primary and secondary water systems and concluded that the types of parameters being monitored, the location of sampling points, and the frequency of sampling... are adequate to detect contamination of the primary, secondary, and auxiliary water systems."
(Inspection Report 84-08)
More strongly supportive of this evaluation is the fact that to date no steam generator tube has failed due to corrosion, nor has any evidence been found that even suggests that corrosion of steam generator internals is taking place. The
+
absence of steam generator corrosion strongly supports the conclusion that FPC's water chemistry program is effective for CR-3, and demonstrates FPC's commitment and ability to maintain good water chemistry without Staff mandates or waiting for the Staff to recommend a water, chemistry program.
The Staff should note that, while FPC's secondary water chemistry program has proven its effectiveness by the absence of steam generator corrosion, this or any other program may not prove effective at other plants with even slightly
' different designs, operating conditions, cooling water chemistries, etc. Hence, generic. water chemistry programs should not be mandated by the Staff. FPC is committed to the continued implementation and betterment (as deemed necessary) of its secondary water chemistry program.
I The sections that follow describe FPC's secondary water chemistry program relative to the concerns of Staff Recommended Action 3.a (Section 2.5 of NUREG-0844).
4.5.1 Chemistry Control 4.5.1.1 Oxygen Control. Water containing dissolved oxygen can be highly corrosive to ferrous metal and, in the presence of ammonia, to copper alloys. The resultant corrosion products can be transported to the steam generators and accumulate.
Corrosion product accumulation. provides a mechanism for concentration of impurities and for uncontrolled local corrosion. Effective oxygen removal is therefore recognized-by FPC to be essential to maintaining high system reliability and steam generator integrity.
At CR-3 oxygen removal is effectively accomplished by a combination of chemical and mechanical deaeration. Chemical deaeration is accomplished by hydrazine which is injected into the condensate system downstream of the condensate demineralizers.
Mechanical deaeration (by the deaerator) is employed to remove the traces of oxygen not scavenged by the hydrazine.
Typically, the oxygen concentration in the feedwater entering the deaerator is 5-10 ppb and is undetectable in the deaerator effluent.
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The addition of Amerzine (catalyzed hydrazine) maintains the dissolved oxygen concentration in the CST at 45 ppb.
4.5.1.2
. pH Control. The rate of corrosion product accumulation is a function of various parameters, among which is pH. Accordingly, pH is strictly maintained at 9.2-9.4 to minimize the corrosion of iron and copper secondary system components and piping.
Ammonium hydroxide Is injected into the condensate system downstream of the condensate demineralizers to adjust system pH.
It should be noted that from initial plant startup in 1977 to August 1984, condensate system pH was maintained at 8.9-9.0. From August 1984 to the end of the la'st operating cycle (March 1985), pH was maintained at 9.2-9.4.
This action resulted in a 60% reduction (based on a comparison of NWT Corporation findings in EPRI NP-2149 and recent integrated sample analyses) of iron oxide t
- transport into the steam generators with nearly no change in copper oxides transport rates.
This action (the raising of the condensate system pH) further demonstrates FPC's commitment to assure steam generator integrity and FPC's willingness to try innovative operating techniques (without regulatory action mandating such) in order to reduce the potential for steam generator tube corrosion.
4.5.1.3 Sodium, Chloride, and Cation Conductivity Control. It is known that sodium plays an important role in the corrosion mechanism causing tube cracking. In addition, chlorides are known to play a major role in tube denting / support plate corrosion and tube pitting.
Accordingly, the concentrations of sodium and chlorides are monitored continuously by on-line instrumentation, and periodically by grab sample analyses.' Cation conductivity is also continuously monitored.
Control of sodium (and correspondingly, chlorides and cation conductivity)in the condensate is assured by a Nuclear Plant Policy which defines criteria in which a salt leak in the condenser is to be presumed and a waterbox should be isolated for repair. Additional control of sodium and chlorides is provided by the policy of removing a demineralizer bed from service and replacing it with new resin once the demineralizer effluent has 2-3 ppb sodium or chloride.
'4.5.1.4 Iron and Copper Control. As stated in Section 4.5.1.2,' the rate of iron and copper transport into the steam generators is dependent on pH. While strides have been made to reduce iron and copper transport (e.g., raising secondary e
system pH), the reduction of iron transport is limited by the presence of copper components.
To prevent excessive corrosion of copper, the pH must be
' i maintained at a value that does not minimize corrosion of iron alloy components.
i The roles' iron and copper oxides play in steam generator fouling and corrosion
. O mechanisms have been described previously.
Accordingly, FPC is currently
'[
involved in an effort to remove copper components, namely the MSR tubing and main condenser tubing, from the secondary system. These efforts will remove J
the sources of copper into the steam generators, and will allow fron transport to L
be minimized.
An integrated sampler is currently being acquired to continuously monitor total iron and copper in the feedwater.
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- 4.5.1.5 Chemistry Control During Shutdown, Startup, and Operation. Procedures exist that include provisions for controlling the chemistry of the reactor coolant, as well as secondary coolant during cold shutdown; startup (including hot standby);
and power operation. These procedures also address the use of the condensate polishing system and steam generator drain lines for ensuring the quality of the feedwater and steam generator water, specifically during startup..
The Chemistry Procedures also provide steps to prevent contamination of the secondary side during shutdown, especially contamination by inleakage of air.
Likewise, instructions for layup as well as criteria for water chemistry parameters during the layup period are given. During startup the procedures require a phased cleanup of the condensate /feedwater train to prevent the transport of solids (especially iron oxides) into the steam generators.
4.5.2 Data Interpretation / Action Initiation Contact Each analyst and his/her supervisor interpret test results. If the result is outside its specified limit, corrective actions are logged on the appropriate log sheet, a Chem / Rad Follow-up Report (FUR), Work Request, or ' a Nonconforming Operations Report (NCOR) and communicated to the Nuclear Shift Supervisor as applicable.
. CR-3 Operations Department routinely responds to the Chemistry Section's concerns when certain parameters change significantly or exceed specifications.
Particularly noted are condenser seawater in-leakage, increasing s oxygen concentrations, and resin bed depletion.
4.5.3 Ar:alytical Methods The continuous monitoring and laboratory techniques employed at CR-3 for the measurement of specific conductivity, cation conductivity, pH, oxygen, sodium hydrazine, chloride, ammonia, silica, iron and copper compare favorably with the EPRI PWR Secondary Water Chemistry Guidelines. CR-3's current analytical capabilities include state-of-the-art instrumentation for performing atomic absorption analyses, ion analyses, and leak testing.
Current plans are to completely refurbish the "in-line" analytical instrumentation for the secondary plant which will include an "on-line" capability for lon chromatography and total organic carbon analyses.
The CR-3 water chemistry program is implemented by means of a weekly i
schedule that is developed by the Nuclear Chemistry and Technical Specification Coordinating Groups. Each task is assigned daily by the Chief Technician in each
[
laboratory and is performed with the aid of a Chemistry Procedure or Surveillance Procedure for Technical Specification requirements.
4.5.3.1 Monitored Parameters l'
Condensate.
The condensate at the discharge of the condensate pumps is continuously monitored for cation conductivity, dissolved oxygen, and pH.
5 j
Specific conduc+1vity, turbidity, tritium, sodium, and chloride are monitored on a
. daily basis. Silica and ammonia concentrations are determined weekly. The pH of the IP-Heater drains is continuously monitored; silica and sodium are
' monitored weekly. The cation conductivity of the auxiliary steam is monitored daily.
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r i:
([l 4-10 L
Condensate Makeup. The quality of water in the CST is monitored weekly for specific and cation conductivity, iron, silica, and phosphate, dissolved oxygen, and ammonia. -
Demineralizer Effluent.
Cation conductivity and sodium are continuously monitored.. Silica, unit flow, specific conductivity, and turbidity are monitored daily.
Demerator Influent and Effluent. The influent is monitored continuously for specific conductivity and pH. The effluent is monitored for pH and hydrazine.
Cation conductivity, pH, and dissolved oxygen are continuously monitored. Silica, hydrazine, ammonia, copper, sulfate, and lead concentrations are determined weekly. Total iron is monitored on a daily basis.
4.5.3.2 Procedures. Analytical procedures are based on the Babcock & Wilcox Water Chemistry Manual, ASTM references, or vendor procedures. Each procedure
. contains guidance relative to the following items: scope, principle, potential interference, definitions, reagents, special apparatus needed, quality control required, a step-wise procedure, calculations required, and other information such as calibration curves. Procedures that involve taking samples from process lines also identify the required lineup of valves.
4.5.4 Data Management 4.5.4.1 Data Recording. The results of each analysis is documented on the appropriate surveillance procedure data sheet by the analyst who performed the test. The results of all analyses are submitted to the Chemistry Supervisor who reviews the results daily.
4.5.4.2 Data Trending. The values of the most important parameters at each sample point are plotted on graphs for trend indication. A computer has been purchased for chemistry trending. ' The software is currently being developed specifically for CR-3 and should be completed within the next year.
4.5.4.3 :
Data Review. - Each analyst and his/her supervisor interpret the test results. If the result is outside its specified limit, corrective actions are logged on the
. appropriate log sheet, a Chem / Rad Follow-up Report (FUR), Work Request, or a Nonconforming Operations Report (NCOR), and communicated to the Nuclear Shift Supervisor as applicable.
4.5.4.4 Data Storane and Retrieval. The surveillance procedure data sheet (s) for each completed analysis is sent to Document Control on site for data storage. A computerized data management system facilitates data retrieval both on site and at the corporate offices.
4.5.5 Surveillance.
As a part of CR-3's Station Self Assessment Program, Chemistry Supervisors are required to observe the performance of at least one chemistry procedure per week. The supervisor is required to document his observations and send them to the Chemistry Superintendent for review.
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4.6
- CONDENSER INSERVICE INSPECTIONS FPC is well aware that industry experience and test programs have demonstrated that steam generator integrity is affected by condenser integrity and materials of construction.
Condenser tube leaks and tube-to-tubesheet joint leakage permit cooling water impurities to enter the condensate and consequently the steam generators. Chlorides, and acid chlorides resulting from cooling water inleakage is known to play a major role in tube denting / support plate corrosion and tube pitting, respectively.
Cooling water inleakage is also a source of ^
sodium, sulfur, and silicon contaminants which are believed to play an important
.part in steam generator tube cracking mechanisms. It is recognized that the condensate demineralizers only provide partial, stop-gap protection during a condenser leak,' and are, therefore, not relied upon to provide a long term alternative to a " tight" condenser. Additionally, air inleakage into the condenser adds oxygen to the condensate, thus increasing the susceptibility of the copper alloy tubes to ammonia attack in the air removal section.
Accordingly, FPC is committed to take those actions considered necessary to minimize cooling water and air inleakage into the condenser. Exemplificative of this commitment is the replacement of the Low Pressure Turbine boot and shaf t seal gaskets during this outage (Refuel V) to reduce condenser air inleakage, and the installation of an on-line condenser tube cleaning system (Amertap) which primarily will minimize load reductions due to biofouling, but secondarily will minimize the potential for biologically-induced corrosion of the condenser tubes (thereby minimizing the potential for cooling water ingress by tube leaks). In addition, corporate engineering, Steam Generator Task Force, and plant staff personnel are currently involved in a review of condenser performance and an evaluation of the need for retubing the condenser. -
FPC considers its current efforts to ensure condenser integrity to be sufficient to address the steam generator tube corrosion concerns associated with condenser tube leakage. The conclusions of NRC Inspection Report 84-08 (stated below) support this evaluation of FPC's condenser activities.
"The inspector considers that the licensee is taking appropriate measures to maintain the integrity of the condensers, and has the capability to detect inleakage of air or circulating cooling water so that protective measures can be taken in a timely manner before the primary coolant boundary (i.e., steam generator tubes) is degraded."
Notwithstanding the NRC inspector's favorable assessment of FPC's condenser integrity efforts, FPC will continue to improve and expand its efforts as considered necessary to ensure the safe, legal, and economical operation of CR-y]
3.
n d
it should be noted however, that FPC concurs with the Steam Generator Owners b
Group position that utilities should be free to establish the condenser inspection j'
and maintenance programs best suited for their individual plants without NRC regulation in this area.
Furthermore, FPC considers a condenser inservice Inspection program to be solely a matter of economic consideration and does not constitute a nuclear safety issue. Past and present FPC activities in this area have demonstrated that there is indeed a strong economic incentive to maintain I
a " tight" condenser, and that this philosophy (of condenser integrity not 4-12 1
constituting a safety issue) does not result in a laxity in condenser maintenance.
Moreover, FPC's activities in this area demonstrate its ability and commitment to develop and implement programs to ensure condenser integrity without waiting for the Staff to recommend or mandate such programs for FPC to follow.
The five points of Staff Recommended Action 3.b (Section 2.6 of NUREG-0844) are addressed in the folio ing sections.
4.6.1 Procedure A Nuclear Plant Policy includes specified actions to be taken based on the degree to which the water in the hotwells becomes contaminated, i.e., based on cation conductivity and sodium concentration.
These actions include the
~ identification and isolation of the affected waterbox and subsequent repair or isolation of the failed section of the condenser.
Although there is not a procedure requiring such, typically 10% of all condenser tubes are inspected by eddy current testing during each refueling outage. During the current refueling outage,10% of the condenser tubes were inspected by eddy current testing. In order to allow trending of tube degradation, the 10% selected in this outage for ECT was approximately the same 10% as was inspected by eddy current testing during the last refueling outage (Refuel IV).
4.6.2 Leak identification and Location Cooling water inleakage into the condenser is detectable by continuous monitoring of the condensate at the discharge of the condensate pumps for conductivity, dissolved oxygen, and pH, and by the analysis of grab samples f rom both hot wells and the inter-tie between the two hotwells. A cation conductivity alarm located in the Control Room allows operators to identify cooling water inleakage.
The air removal pump rotameter and measurement of condenser vacuum permit identification of air inleakage. Ultrasound and helium detection are used to locate the source of air inleakage. In addition, silica, sodiuin, and chloride in the condensate are determined on a daily frequency. A helium leak detector is employed to locate small oxygen and seawater leaks in the condenser.
Soap is used to locate large leaks.
4.6.3 Leak Repair Identifiable leaking tubes are plugged. Tubes identified by eddy current testing to have 60% or more wall thinning are plugged. Sawdust is added initially to the circulating cooling water to temporarily plug minor leaks. Applying an epoxy coating to the tubesheet has proven to be an effective short term fix for tube-to-tubesheet joint leaks. Select tubes have been rerolled to eliminate leaking in the tube-to-tubesheet joint. The tightening of connections on flanges, sealing joints with silicone rubber, replacing problem components (such as the LP turbine boot) and the performance of normal maintenance are remedial actions for condenser air inleakage.
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@i, 4.6.4 Leakage Cause Determination Known degraded tubes are typically pulled during each outage and subjected to metallurgical analysis for determination of the failure mechanism. The results of such failure analyses permit the development of appropriate corrective action to preclude similar failures in the future. During the current refueling outage, three (3) degraded tubes were pulled for metallurgical analysis. Additionally, the waterboxes were visually inspected and the tubes' inlet ends were inspected for any evidence of errosion. Direction for identifying the cause of air inleakage by testing for vacuum leaks with helium at over 300 potential leak locations is given by a Performance Monitoring Guideline.
4.6.5 Preventative Maintenance A preventative maintenance procedure, " Inspection / Cleaning / Shooting and Plugging of Heat Exchangers", describes condenser preventative maintenance activities. In addition, as a part of FPC's condenser preventative maintenance effort, the following activities are (or are being) performed.
o Installation of an Amertap condenser tube cleaning system.
o Epoxy coating of the tubesheets to preclude tube-to-tubesheet joint leakage.
o Maintenance (and replacement of as necessary) of sacrificial anodes (to prevent galvanic corrosion of the tubesheet and waterboxes).
o Trending of plugged condenser tubes.
o Trending air inleakage.
o Field testing to verify sources of air inleakage.
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5.0 STEAM GENERATOR TUBE RUPTURE MITIGATION 5.1 PRIM ARY-TO-SECOND ARY LEAK AGE LIMITS CR-3 Technical Specifications (T.S. 3.4.6.2) !!mit total primary-to-secondary leakage through the steam generators to 1 gpm. CR-3 Technical Specifications do not have the additional limit of 500 gpd (0.35 gpm) primary-to-secondary leakage per steam generator stated in Staff Recommended Action 4 (Section 2.8 of NUREG-0844).
5.2 COOLANT IODINE ACTIVITY LIMIT CR-3 Technical Specification limits (T.S. 3.4.8) and surveillances (T.S. 4.4.8) for coolant lodine activity are consistent with the Standard Technical Specifications.
CR-3 has high head high pressure safety injection pumps. Hence, the portion of Staff Recommended Action 5 (Section 2.9 of NUREG-0844) relative to low head high pressure safety injection pumps is not applicable to CR-3.
5.3 SAFETY INSPECTION SIGNAL RESET FPC has already performed Staff Recommended Action 6 (Section 2.11 of NUREG-0844). Prior to the issuance of Generic Letter 85-02, a review of the control logic associated with the makeup /high pressure injection pump suction flow path was initiated. As a result of this review, a modification has been performed to provide a more reliable suction source in the event that the makeup tank (normal suction source) is -drained too low.
Previously, suction switchover from the makeup tank to the borated water storage tank occurred only during an engineered safeguards (ES) actuation.
The aforementioned modification will cause switchover to occur under conditions of either an ES actuation or a low makeup tank level.
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APPENDIX REQUEST FOR INFORMATION CONCERNING CATEGORY C-2 STEAM GENERATOR TUBE INSPECTIONS Information Requested 1.
What factors do, or would, the licensee or applicant consider in determining:
Whether additional tubes should be inspected beyond what is required by the a.
Technical Specifications?
b.
Whether all steam generators should be included in the inspection program?
c.
When the steam generators should be reinspected?
2.
To what extent do these factors include consideration of the degradation mechanism itself and its potential for causing a tube to be vulnerable to rupture during severe transients or postulated accident before rupture or leakage of that tube occurs during normal operation.
FPC Response FPC has not experienced sufficient tube degradation to warrant the development of positions regarding our potential response to C-2 indications. However, FPC considers more complex pre-planned examinations to be premature until the nature, distribution, location and extent of degraded tubes on a plant-specific basis is better understood. Sufficient time exists for licensees, the NRC, and others to evaluate expanded inspections upon discovery and reporting.
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